The life of a typical hydrocarbon producing well can be broadly classified in three stages. The first stage includes the drilling of the well borehole, where it is desirable to measure properties of earth formations penetrated by the borehole and to steer the direction of the borehole while drilling. The second stage includes testing of formations penetrated by the borehole to determine hydrocarbon content and producibility. The third stage includes monitoring and controlling production typically throughout the life of the well. All stages typically employ a downhole assembly that contains one or more sensors responsive to stage related drilling, formation, or production parameters of interest. Response data from the one or more sensors are telemetered, via a first or “borehole” transceiver, to the surface of the earth. Response data are received by a second or “surface” transceiver for processing and interpretation. Conversely, it is desirable to transmit data via the surface transceiver to the downhole transceiver to control stage related drilling, testing or production operations.
In the stages discussed above, it is often not operationally feasible to use a “hard wire” communication link, such as one or more electrical or fiber optic conductors, between the downhole transceiver and the surface transceiver. This is especially true in the borehole drilling stage, where measures of parameters of formations penetrated by the borehole are of interest. When hard wire communication links are not feasible, electromagnetic (EM) telemetry systems offer one means for communicating between downhole and surface transceivers.
Systems for measuring geophysical and other parameters within the vicinity of a well borehole typically fall within two categories. The first category includes systems that measure parameters after the borehole has been drilled. These systems include wireline logging; tubing conveyed logging, slick line logging, production logging, permanent downhole sensing devices and other techniques known in the art. Memory type or hard wire communication links are typically used in these systems. The second category includes systems that measure formation and borehole parameters while the borehole is being drilled. These systems include measurements of drilling and borehole specific parameters commonly known as “measurement-while-drilling” (MWD), measurements of parameters of earth formation penetrated by the borehole commonly known as “logging-while-drilling” (LWD), and measurements of seismic related properties known as “seismic-while-drilling” or (SWD). For brevity, systems that measure parameters of interest while the borehole is being drilled will be referred to collectively in this disclosure as “MWD” systems. Within the scope of this disclosure, it should be understood that MWD systems also include logging-while-drilling and seismic-while-drilling systems.
A MWD system typically comprises a borehole assembly operationally attached to a downhole end of a drill string. The borehole assembly typically includes at least one sensor for measuring at least one parameter of interest, an electronics element for controlling and powering the sensor, and a downhole transceiver for transmitting sensor response to the surface of the earth for processing and analysis. The borehole assembly is terminated at the lower end with a drill bit. A rotary drilling rig is operationally attached to an upper end of the drill string. The action of the drilling rig rotates the drill string and borehole assembly thereby advancing the borehole through the action of the rotating drill bit. A surface transceiver is positioned remote from the borehole assembly and typically in the immediate vicinity of the drilling rig. The surface transceiver receives telemetered data from the downhole transceiver. Received data are typically processed using surface equipment, and one or more parameters of interest are recorded as a function of depth within the well borehole thereby providing a “log” of the one or more parameters. Hard wire communication links between the downhole and surface transceivers are operationally difficult because the borehole assembly containing the downhole transceiver is rotated by the drill string with respect to the surface transceiver.
In the absence of a hard wire link, several techniques can be used as a communication link for the telemetry system. These systems include drilling fluid pressure modulation or “mud pulse” systems, acoustic systems, and electromagnetic systems.
Using a mud pulse system, a downhole transmitter induces pressure pulses or other pressure modulations within the drilling fluid used in drilling the borehole. The modulations are indicative of one or more parameters of interest, such as response of a sensor within the borehole assembly. These modulations are subsequently measured typically at the surface of the earth using a receiver means, and one or more parameters of interest are extracted from the modulation measurements.
A downhole transmitter of an acoustic telemetry induces amplitude and frequency modulated acoustic signals within the drill string. The signals are indicative of one or more parameters of interest. These modulated signals are measured typically at the surface of the earth by an acoustic receiver means, and the one or more parameters of interest are extracted from the measurements.
Electromagnetic telemetry systems can employ a variety of techniques. Using one technique, electromagnetic signals are modulated according to a sensor response to represent one or more parameters of interest. In one embodiment, these signals are transmitted from a downhole EM transceiver, through intervening earth formation, and detected as a voltage or a current using a surface transceiver that is typically located at or near the surface of the earth. The one or more parameters of interest are extracted from the detected signal. Using another electromagnetic technique, a downhole transceiver creates a current within the drill string, and the current travels along the drill string. This current is typically created by imposing a voltage across a non-conducting section in the downhole assembly. The current is modulated according to the sensor response to represent the one or more parameters of interest. A voltage between the drilling rig and a remote ground is generated by the current and is measured by a surface transceiver, which is at the surface of the earth. The voltage is usually between a wire attached to the drilling rig or casing at the surface and a wire that leads to a grounded connection remote from the rig. Again, one or more parameters of interest are extracted from the measured voltage. Alternately, the one or more parameters of interest can be extracted from a measure of current.
The rotation of the drill string produces electromagnetic interference or electromagnetic “noise” in previously discussed EM telemetry systems. This noise can greatly degrade the signal of an electromagnetic telemetry system. The noise is typically cyclical or “synchronous” thereby mimicking the repetitive action of the rotating drill string. Electromagnetic noise can also be produced by the action of the drilling rig mud pump. This noise is also typically cyclical mimicking the repetitive action of the mud pump. There can be other sources of typically cyclical electromagnetic noise induced in an electromagnetic telemetry system. These sources include electric motors in the vicinity of the drilling rig, overhead wires transmitting alternating electric current, and any number and types of electromechanical apparatus found at a drilling site.
To summarize, noise from any source greatly degrades the signal of any type of electromagnetic telemetry system. This is especially true in “first stage” discussed above, which includes the drilling of the borehole using MWD systems using electromagnetic telemetry systems. The “second stage” discussed above includes testing of formations penetrated by the borehole to determine hydrocarbon content and producibility. If an electromagnet telemetry system rather than hard-wired telemetry systems is used, noise degradation can again be a significant problem. Finally, the “third stage” discussed above includes monitoring and controlling production typically throughout the life of the well. These monitor and control systems can utilize electromagnetic rather than hard-wired telemetry systems. Again, noise degradation in electromagnetic telemetry systems can be significant. Noise encountered in all three stages is often cyclical or synchronous, and can result from drill string rotation, the action of pumps, the operation of electric motors, electromagnetic radiation from nearby power lines, cyclical radio beacon signal, and the like.